CN112262202B

CN112262202B - Method and apparatus for hydrocracking with heavy fractionation column

Info

Publication number: CN112262202B
Application number: CN201980038864.3A
Authority: CN
Inventors: 唐纳德·A·艾曾加; 哈里·S·巴杰帕伊; 理查德·K·霍恩
Original assignee: UOP LLC
Current assignee: Honeywell UOP LLC
Priority date: 2018-06-26
Filing date: 2019-06-26
Publication date: 2023-04-28
Anticipated expiration: 2039-06-26
Also published as: WO2020006100A1; US10822556B2; CN112262202A; US20190390120A1

Abstract

The present invention relates to a process and apparatus for hydrocracking a hydrocarbon stream that feeds a cold stripped stream and a hot stripped stream to a reboil product fractionation column. The product fractionation bottoms stream is passed to a heavy fractionation column, which may be stripped and may be under vacuum.

Description

Method and apparatus for hydrocracking with heavy fractionation column

Technical Field

The field is the recovery of hydrocracked hydrocarbon streams with improved efficiency.

Background

Hydrotreating may include a process for converting hydrocarbons into more valuable products in the presence of a hydrotreating catalyst and hydrogen. Hydrocracking is a hydrotreating process in which hydrocarbons are cracked into lower molecular weight hydrocarbons in the presence of hydrogen and a hydrocracking catalyst. Depending on the desired output, the hydrocracking unit may contain one or more catalyst beds, which may be the same or different. Hydrocracking may be performed using one or two hydrocracking reactor stages.

The hydrotreating recovery section typically includes a series of separators in a separation section to separate gaseous materials from liquid materials and to cool and decompress the liquid stream in preparation for fractionation into products. The hydrogen is recovered for recycle to the hydrotreating unit. A typical hydrocracking recovery section includes six columns. The stripper uses a vapor stream to strip hydrogen sulfide from the liquid hydrocracked stream. The liquid stripped stream is fractionated in a deethanizer, the overhead of which is absorbed with a sponge in an absorber along with the vapor stripper overhead stream to produce LPG. The product fractionation column separates the stripped liquid hydrocracked stream into an overhead fractionation stream (possibly a distillate side product stream) comprising naphtha and a bottoms stream comprising unconverted oil (comprising distillate). The product fractionation overhead stream and the deethanizer bottoms stream are fractionated in a debutanizer fractionation column into a debutanizer overhead stream comprising LPG and a debutanizer bottoms stream comprising naphtha. The debutanizer bottoms stream is fractionated in a naphtha splitter into a light naphtha overhead stream and a heavy naphtha bottoms stream.

The hydrotreated recovery section including the fractionation column relies on external facilities originating outside the hydrotreatment unit to provide a heater load for gasifying the fractionated materials. The fractionation section, which is more dependent on the heat generated in the hydrotreating unit, is more energy efficient than the external facilities. Stripping columns typically rely on steam stripping to separate volatile materials from heavier hydrocarbon materials.

In some areas, diesel demand is lower than demand for lighter fuel products. Distillate or diesel hydrocracking is proposed to produce lighter fuel products such as naphtha and Liquefied Petroleum Gas (LPG). The naphtha product stream may be proposed for petrochemical production and considered as feed to a reformer unit followed by an aromatics complex (aromatics complex).

Thus, there is a continuing need to increase the efficiency of processes for recovering petrochemical feedstock from hydrocracked distillate feedstock.

Disclosure of Invention

A process and apparatus for hydrocracking a hydrocarbon stream feeds a cold stripped stream and a hot stripped stream to a reboil product fractionation column. The product fractionation bottoms stream is passed to a heavy fractionation column, which may be stripped and may be under vacuum. A diesel stream and a kerosene stream may be provided that are not further stripped to meet product specifications.

Drawings

Fig. 1 is a simplified process flow diagram.

Fig. 2 is an alternative embodiment of fig. 1.

Definition of the definition

The term "communicating" means operatively permitting flow of material between enumerated components.

The term "downstream communication" means that at least a portion of the substance flowing toward the body in the downstream communication may operably flow from the object with which it is in communication.

The term "upstream communication" means that at least a portion of the substance flowing from the body in the upstream communication may be operatively flowing toward the subject in communication therewith.

The term "directly connected" means that the stream from the upstream component enters the downstream component without passing through the conversion unit without undergoing a change in composition due to physical or chemical conversion.

The term "indirect communication" means that the stream from the upstream component enters the downstream component after undergoing a change in composition by a separation or conversion unit due to physical separation or chemical conversion.

The term "bypass" means that the subject loses downstream communication with the bypass subject, at least within the scope of the bypass.

The term "column" means one or more distillation columns for separating one or more components of different volatile materials. Unless otherwise indicated, each column includes a condenser on the top of the column for condensing and refluxing a portion of the top stream back to the top of the column, and a reboiler at the bottom of the column for vaporizing and returning a portion of the bottom stream to the bottom of the column. The feed to the column may be preheated. The top pressure is the pressure of the overhead vapor at the vapor outlet of the column. The bottom temperature is the liquid bottom outlet temperature. The overhead line and the bottom line refer to the net lines downstream from any reflux or reboiling column to the column. The stripper column may omit a reboiler at the bottom of the column and instead provide the heating requirements and separation dynamics for the liquefied inert medium, such as steam. The stripper typically feeds the top tray and takes the stripped product from the bottom of the column.

As used herein, the term "T5" or "T95" means the temperature at which a sample derived using ASTM D-86 or TBP boils 5 liquid volume percent or 95 liquid volume percent (as the case may be), respectively.

As used herein, the term "external facility" means a facility that originates outside of the hydrotreating unit, which typically provides a heater load for gasifying the fractionated substances. The external facility may provide heater load through a fired heater, a steam heat exchanger, and a hot oil heater.

As used herein, the term "initial boiling point" (IBP) means the temperature at which a sample begins to boil using ASTM D-86 or TBP.

As used herein, the term "end point" (EP) means the temperature at which a sample derived using ASTM D-86 or TBP boils throughout.

As used herein, the term "true boiling point" (TBP) means a test method for determining the boiling point of a substance that meets ASTM D2892 for producing liquefied gases, distillate fractions and residues of standardized quality for which analytical data can be obtained, and determining the yield of such fractions by both mass and volume from which a plot of distillation temperature versus mass% is obtained in a column having a reflux ratio of 5:1 using fifteen theoretical plates.

As used herein, the term "naphtha boiling range" means that the hydrocarbon boils in the IBP range between 0 ℃ (32°f) and 100 ℃ (212°f) or T5 between 15 ℃ (59°f) and 100 ℃ (212°f) using a TBP distillation process, and the "naphtha fractionation point" includes T95 between 150 ℃ (302F) and 200 ℃ (392°f).

As used herein, the term "kerosene boiling range" means that the hydrocarbon boils in the range of IBPs between 125 ℃ (257°f) and 175 ℃ (347°f) using a TBP distillation process, and the "kerosene fractionation point" includes endpoints between 215 ℃ (419°f) and 260 ℃ (500°f).

As used herein, the term "diesel boiling range" means that the hydrocarbon boils in the range of IBP between 125 ℃ (257°f) and 260 ℃ (500°f) and preferably no more than 175 ℃ (347°f) or T5 between 150 ℃ (302°f) and 260 ℃ (500°f) and preferably no more than 200 ℃ (392°f) using a TBP distillation process, and "diesel fractionation point" includes T95 between 343 ℃ (650°f) and 399 ℃ (750°f).

As used herein, the term "separator" means a vessel having one inlet and at least one overhead vapor outlet and one bottom liquid outlet, and may also have an aqueous stream outlet from a tank (boot). The flash tank is one type of separator that may be in downstream communication with a separator that may be operated at a higher pressure.

As used herein, the term "major" or "majority" means greater than 50%, suitably greater than 75%, and preferably greater than 90%.

As used herein, the term "C _x "is understood to mean a molecule having the number of carbon atoms indicated by the subscript" x ". Similarly, the term "C _x "means a molecule containing less than or equal to x, and preferably x and fewer carbon atoms. The term "C _x "refers to molecules having greater than or equal to x, and preferably x and more carbon atoms.

As used herein, the term "component-rich stream" means that the rich stream exiting the vessel has a greater concentration of components than the feed to the vessel.

As used herein, the term "lean component stream" means that the lean stream exiting the vessel has a smaller concentration of components than the feed to the vessel.

Detailed Description

The proposed process and apparatus for recovering products from hydrocracked distillates include cold and hot strippers, debutanizers, product fractionation columns, sponge absorber columns and heavy fractionation columns. The cold stripper and the hot stripper may have integrated reboilers. The cold and hot stripped streams are fed to a product fractionation column comprising a prefractionation column from which the prefractionation column overhead stream and prefractionation column bottoms stream are passed to the product fractionation column. The product fractionation column produces three products: an overhead stream comprising Light Naphtha (LN), an intermediate stream comprising Heavy Naphtha (HN), and a bottoms unconverted oil (UCO) stream, thereby eliminating the need for a separate naphtha splitter column. The cold stripper or the hot stripper can provide a liquid stripper overhead stream and a stripping stream. The liquid stripper overhead stream can be fractionated to provide a light fractionation overhead stream, a light fractionation intermediate stream, and a light fractionation bottoms stream in a single light fractionation column, thereby eliminating the need for a separate deethanizer. Deethanizer and naphtha splitter columns do not need to meet the desired specifications for downstream units, thereby saving capital and operating costs. The cold stripper or the hot stripper may also provide a vapor stripper overhead stream from which LPG hydrocarbons may be absorbed by the absorbent from the stripper stream. The product fractionation bottoms stream can be passed to a heavy fractionation column to provide a distillate stream and an unconverted oil stream, which can be stripped and can be under vacuum.

In fig. 1, a hydrotreating unit 10 for hydrotreating hydrocarbons includes a hydrotreating reactor section 12, a separation section 14, and a recovery section 16. The hydrotreating unit 10 may be designed for hydrocracking heavier hydrocarbons into distillate, such as diesel, kerosene, naphtha, and LPG products. For example, the VGO stream in hydrocarbon line 18 and the hydrogen stream in hydrogen line 20 are fed to the hydrotreating reactor section 12. In one aspect, the diesel stream can be lighter hydrocarbons in the hydrocarbon line 18. The hydrotreated effluent is separated in separation section 14 and fractionated into products in recovery section 16.

The hydrotreating that occurs in the hydrotreating reactor section 12 may be optionally hydrocracked prior to hydrotreating. Hydrocracking is the preferred process in the hydrotreating reactor section 12. Thus, the term "hydrotreating" will include the term "hydrocracking" herein.

In one aspect, the methods and apparatus described herein can be used to hydrocracke a hydrocarbon feed stream comprising distillate. Suitable distillates may include a diesel feed boiling in the range of T5 between 125 ℃ (257°f) and 175 ℃ (347°f), between 150 ℃ (302°f) and 200 ℃ (392°f), and/or a "diesel fractionation point" comprising T95 between 343 ℃ (650°f) and 399 ℃ (750°f) using a TBP distillation process. A particularly suitable feed stream may be Vacuum Gas Oil (VGO), which is typically a hydrocarbon material produced by vacuum fractionation of atmospheric residuum having a boiling point range of IBP of at least 232 ℃ (450°f), T5 of 288 ℃ (550°f) to 343 ℃ (650°f), T95 between 510 ℃ (950°f) and 570 ℃ (1,058 °f), and/or EP of no more than 626 ℃ (1,158°f).

The hydrogen stream in hydrogen line 20 may be split off from hydrotreated hydrogen line 22. The hydrogen stream in line 20 can be a hydrotreated hydrogen stream. The hydrotreated hydrogen stream can be added to the hydrocarbon stream in hydrocarbon line 18 to provide a hydrocarbon feed stream in hydrocarbon feed line 26. The hydrocarbon feed stream in hydrocarbon feed line 26 may be heated by heat exchange with the hydrocracked stream in hydrocracked effluent line 44 and in a fired heater. The heated hydrocarbon feedstream in the hydrocarbon feed line 26 can be fed to an optional hydrotreating reactor 30.

Hydrotreating is a process in which hydrogen is contacted with hydrocarbons in the presence of a hydrotreating catalyst which is primarily used to remove heteroatoms such as sulfur, nitrogen, and metals from hydrocarbon feedstocks. In the hydrotreatment, hydrocarbons having double bonds and triple bonds can be saturated. Aromatic compounds may also be saturated. Thus, the term "hydrotreating" may include the term "hydrotreating" herein.

The hydroprocessing reactor 30 can be a fixed bed reactor that includes one or more vessels, a single or multiple catalyst beds in each vessel, and various combinations of hydroprocessing catalysts in one or more vessels. It is contemplated that the hydroprocessing reactor 30 operates in a continuous liquid phase in which the volume of liquid hydrocarbon feed is greater than the volume of hydrogen. The hydroprocessing reactor 30 can also be operated in a conventional continuous gas phase, moving bed or fluidized bed hydroprocessing reactor. The hydrotreatment reactor 30 can provide a single pass conversion of 10 vol% to 30 vol%.

The hydroprocessing reactor 30 may include a guard bed of a particular material for pressure drop relief followed by one or more high quality hydroprocessing catalyst beds. The guard bed filters the particles and picks up contaminants in the hydrocarbon feed stream, such as metals like nickel, vanadium, silicon and arsenic, which deactivate the catalyst. The guard bed may contain materials similar to the hydrotreating catalyst. Make-up hydrogen may be added at an interstage location between catalyst beds in hydroprocessing reactor 30.

Suitable hydrotreating catalysts are any known conventional hydrotreating catalysts and include those which consist of at least one group VIII metal (preferably subway, cobalt and nickel, more preferably cobalt and/or nickel) and at least one group VI metal (preferably molybdenum and tungsten) on a high surface area support material (preferably alumina). Other suitable hydrotreating catalysts include zeolite catalysts, as well as noble metal catalysts, wherein the noble metal is selected from palladium and platinum. It is within the scope of this specification to use more than one type of hydrotreating catalyst in the same hydrotreating reactor 30. The group VIII metal is typically present in an amount in the range of 2 wt% to 20 wt%, preferably 4 wt% to 12 wt%. The group VI metal will typically be present in an amount in the range of 1 to 25 wt%, preferably 2 to 25 wt%.

Preferred hydrotreating reaction conditions include a temperature of 290 ℃ (550°f) to 455 ℃ (850°f), suitably 316 ℃ (600°f) to 427 ℃ (800°f), and preferably 343 ℃ (650°f) to 399 ℃ (750°f), a pressure of 2.8MPa (gauge) (400 psig) to 17.5MPa (gauge) (2,500 psig), 0.1hr ^-1 Suitably 0.5hr ^-1 For 5hr ^-1 Preferably 1.5hr ^-1 For 4hr ^-1 Liquid hourly space velocity of fresh hydrocarbonaceous feedstock of 84Nm ³ /m ³ (500 scf/bbl) to 1,250Nm ³ /m ³ Oil (7,500 scf/bbl), preferably 168Nm ³ /m ³ Oil (1,000 scf/bbl) to 1,011Nm ³ /m ³ The hydrogen rate of the oil (6,000 scf/bbl), and the hydrotreating catalyst or combination of hydrotreating catalysts.

The hydrocarbon feed stream in hydrocarbon feed line 18 may be hydrotreated with the hydrotreated hydrogen stream from hydrotreated hydrogen line 20 over the hydrotreating catalyst in hydrotreatment reactor 30 to provide a hydrotreated stream that exits hydrotreatment reactor 30 in hydrotreated effluent line 32. The hydrotreated stream still boils predominantly in the boiling range of the feed stream and can be considered a hydrocracked feed stream. The hydrogen loaded with ammonia and hydrogen sulfide may be removed from the hydrocracking feed stream in a separator, but the hydrocracking feed stream is suitably fed directly to the hydrocracking reactor 40 without separation. The hydrocracking feed stream may be mixed in a hydrocracking hydrogen line 21 with a hydrocracking hydrogen stream taken from a hydrotreating hydrogen line 22 and fed to the hydrocracking reactor 40 through an inlet for hydrocracking.

Hydrocracking refers to the process of cracking hydrocarbons in the presence of hydrogen to lower molecular weight hydrocarbons. The hydrocracking reactor 40 may be a fixed bed reactor comprising one or more vessels, a single or multiple catalyst beds 42 in each vessel, and various combinations of hydrotreating and/or hydrocracking catalysts in one or more vessels. The hydrocracking reactor 40 is contemplated to operate in a continuous liquid phase in which the volume of the liquid hydrocarbon feed is greater than the volume of hydrogen. Hydrocracking reactor 40 may also be operated in a conventional continuous gas phase, moving bed or fluidized bed hydrocracking reactor.

The hydrocracking reactor 40 includes a plurality of hydrocracking catalyst beds 42. If the hydrocracking reactor section 12 does not include a hydrotreating reactor 30, the catalyst bed 42 in the hydrocracking reactor 40 may include a hydrotreating catalyst for saturating, demetallizing, desulfurizing, or denitrifying the hydrocarbon feed stream prior to hydrocracking the hydrocarbon feed stream with the hydrocracking catalyst in a subsequent vessel or the catalyst bed 42 in the hydrocracking reactor 40.

The hydrotreated feed stream is hydrocracked over a hydrocracking catalyst in a hydrocracking reactor 40 in the presence of a hydrocracking hydrogen stream from a hydrocracking hydrogen line 21 to provide a hydrocracked stream. The hydrogen manifold may deliver a make-up hydrogen stream to one, some, or each of the catalyst beds 42. In one aspect, make-up hydrogen is added to each hydrocracking catalyst bed 42 at an inter-stage location between adjacent beds, so that the make-up hydrogen mixes with the hydrotreated effluent exiting the upstream catalyst bed 42 before entering the downstream catalyst bed 42.

The hydrocracking reactor may provide a total conversion of at least 20% by volume, typically greater than 60% by volume, of the hydrotreated hydrocarbon stream in the hydrocracking feed line 32 to provide a product having a boiling point below the fractionation point of the heaviest desired product, typically diesel or naphtha. Hydrocracking reactor 40 may operate at partial conversion of greater than 30% by volume of the feed or at least 90% by volume of full conversion based on total conversion. Hydrocracking reactor 40 may be operated under mild hydrocracking conditions, which will provide a total conversion of the hydrocarbon feed stream to 20% to 60% by volume, preferably 20% to 50% by volume, of the product boiling below the desired fractionation point.

The hydrocracking catalyst may utilize an amorphous silica alumina binder or zeolite binder upon which is deposited a group VIII metal hydrogenation component. The additional metal hydrogenation component may be selected from group VIB for incorporation into the binder.

Zeolite cracking binders are sometimes referred to in the art as molecular sieves and are typically composed of silica, alumina, and one or more exchangeable cations such as sodium, magnesium, calcium, rare earth metals, and the like. It is also characterized by crystal pores having a relatively uniform diameter of between 4 and 14 angstroms. It is preferred to use zeolites having a relatively high silica/alumina molar ratio (between 3 and 12). Suitable zeolites found in nature include, for example, mordenite, stilbite, heulandite, ferrierite, cyclozeolite, chabazite, erionite and faujasite. Suitable synthetic zeolites include, for example, B, X, Y and L crystal types, such as synthetic faujasites and mordenites. Preferred zeolites are those having a crystal pore size of between 8 and 12 angstroms, wherein the silica/alumina molar ratio is from 4 to 6. One example of a zeolite falling within the preferred group is a synthetic Y molecular sieve.

Naturally occurring zeolites are generally present in the sodium form, alkaline earth metal form or in mixed form. Synthetic zeolites are almost always prepared in the sodium form. In any case, for use as a cleavage matrix, it is preferred that most or all of the original zeolite monovalent metal is ion exchanged with a multivalent metal and/or with an ammonium salt, and then heated to decompose the ammonium ions associated with the zeolite, leaving at their place hydrogen ions and/or exchange sites that actually remove cations by further removal of water. Hydrogen or "cation-removing" Y zeolites of this nature are more particularly described in US 3,130,006.

The mixed multivalent metal-hydrogen zeolite can be prepared by exchanging ions with an ammonium salt, then partially back exchanging with a multivalent metal salt, and then calcining. In some cases, such as in the case of synthetic mordenite, the hydrogen form may be prepared by direct acid treatment of an alkali metal zeolite. In one aspect, preferred split binders are those lacking at least 10 wt% and preferably at least 20 wt% of metal cations based on the initial ion exchange capacity. In another aspect, the ideal and stable class of zeolites are those in which the hydrogen ions meet an ion exchange capacity of at least 20 wt.%.

The active metals used as hydrogenation components in the preferred hydrocracking catalysts of the present invention are those of group VIII; i.e., iron, cobalt, nickel, ruthenium, rhodium, palladium, osmium, iridium, and platinum. In addition to these metals, other promoters may be used in combination, including group VIB metals, such as molybdenum and tungsten. The amount of hydrogenation metal in the catalyst may vary within wide limits. In general, any amount between 0.05 wt% and 30 wt% may be used. As the noble metal, it is generally preferable to use 0.05 to 2% by weight of the noble metal.

The hydrogenation metal is incorporated by contacting the base material with an aqueous solution of a suitable compound of the desired metal, wherein the metal is present in cationic form. After addition of the selected hydrogenation metal or metals, the resulting catalyst powder is then filtered, dried, pelletized with added lubricants, binders, etc., if desired, and calcined in air at a temperature of, for example, 371 ℃ (700°f) to 648 ℃ (1, 200°f) to activate the catalyst and decompose ammonium ions. Alternatively, the base component may be formed into pellets, followed by the addition of the hydrogenation component and activation by calcination.

The above catalyst may be employed in undiluted form or the powdered catalyst may be mixed and co-pelletized with other relatively less active catalysts, diluents or binders such as alumina, silica gel, silica-alumina co-gel, activated clay, etc. in proportions ranging between 5 and 90 wt.%. These diluents may be employed as such or they may contain a minor proportion of added hydrogenation metals, such as group VIB and/or group VIII metals. Additional metal promoted hydrocracking catalysts may also be used in the process of the present invention, including, for example, aluminum phosphate molecular sieves, crystalline chrome silicates (Crystalline chromosilicates), and other crystalline silicates. Crystalline chrome silicates are more fully described in US 4,363,178.

By one approach, the hydrocracking conditions may include a temperature of 290 ℃ (550°f) to 468 ℃ (875°f), preferably 343 ℃ (650°f) to 445 ℃ (833°f), a pressure of 4.8MPa (gauge) (700 psig) to 20.7MPa (gauge) (3,000 psig), 0.4hr ^-1 To 2.5hr ^-1 Liquid Hourly Space Velocity (LHSV) of 421Nm ³ /m ³ (2,500 scf/bbl) to 2,227 Nm ³ /m ³ Hydrogen rate of oil (15,000 scf/bbl). If mild hydrocracking is desired, the conditions may include a temperature of 315 ℃ (600°f) to 441 ℃ (825°f), a pressure of 5.5MPa (gauge) (800 psig) to 13.8MPa (gauge) (2,000 psig) or more typically 6.9MPa (gauge) (1,000 psig) to 11.0MPa (gauge) (1,600 psig), 0.5hr ^-1 For 2hr ^-1 And preferably 0.7hr ^-1 Up to 1.5hr ^-1 Liquid Hourly Space Velocity (LHSV) of 421Nm ³ /m ³ Oil (2,500 scf/bbl) to 1,685Nm ³ /m ³ Hydrogen rate of oil (10,000 scf/bbl).

The hydrocracked stream may leave the hydrocracking reactor 40 in a hydrocracked line 44 and be separated in a separation section 14 which is in downstream communication with the hydrocracking reactor 40 and optionally the hydrotreating reactor 30. The separation section 14 includes one or more separators in downstream communication with a hydrotreating reactor including a hydrotreating reactor 30 and/or a hydrocracking reactor 40. In one aspect, the hydrocracked stream in hydrocracking line 44 may be heat exchanged with the hydrocarbon feed stream in hydrocarbon feed line 26 to be cooled prior to entering thermal separator 46.

The thermal separator separates the hydrocracked stream in the hydrocracked line 44 to provide a hydrocarbon-containing hot vapor hydrocracked stream in a hot overhead line 48 and a hydrocarbon-containing hot liquid hydrocracked stream in a hot bottom line 50. The thermal separator 46 may be in downstream communication with the hydrocracking reactor 40. The thermal separator 46 operates at 150 ℃ (300°f) to 371 ℃ (700°f), and preferably at 175 ℃ (350°f) to 260 ℃ (500°f). The thermal separator 46 may be operated at a slightly lower pressure than the hydrocracking reactor 40, which results in a pressure drop across the intervening equipment. The thermal separator may be operated at a pressure between 3.4MPa (gauge) (493 psig) and 20.4MPa (gauge) (2,959 psig). The temperature of the hydrocarbon-containing hot gas hydrocracked stream in hot overhead line 48 may be the operating temperature of the thermal separator 46.

The hot vapor hydrocracked stream in hot overhead line 48 may be cooled prior to entering cold separator 52. Ammonia and hydrogen sulfide are formed as a result of the reaction occurring in the hydrocracking reactor 40, wherein nitrogen, chlorine and sulfur are removed from the feed. At the characteristic sublimation temperature, ammonia and hydrogen sulfide will combine to form ammonium disulfide, and ammonia and chlorine will combine to form ammonium chloride. Each compound has a characteristic sublimation temperature that can allow the compound to coat equipment, particularly heat exchange equipment, thereby compromising equipment performance. To prevent the deposition of ammonium disulfide or ammonium chloride salts in the hot overhead line 48 carrying the hot vapor hydrocracked stream, an appropriate amount of wash water may be introduced into the hot overhead line 48 upstream of the cooler at a point in the hot overhead line 48 where the temperature is above the characteristic sublimation temperature of either compound.

The hot vapor hydrocracked stream may be separated in cold separator 52 to provide a cold vapor hydrocracked stream comprising a hydrogen-rich gas stream in cold column overhead line 54 and a cold liquid hydrocracked stream in cold column bottoms line 56. The cold separator 52 is used to separate hydrogen-rich gas from hydrocarbon liquids in the hydrocracked stream for recycle to the hydrocracking reactor 40 in the cold tower overhead line 54. Thus, the cold separator 52 is in downstream communication with the hot overhead line 48 of the hot separator 46 and the hydrocracking reactor 40. Cold separator 52 may be operated at 100°f (38 ℃) to 150°f (66 ℃), suitably 115°f (46 ℃) to 145°f (63 ℃) and just below the pressure of hydrocracking reactor 40 and hot separator 46 (taking into account the pressure drop across the intervening equipment) to maintain hydrogen and light gases at the top of the column and typically liquid hydrocarbons at the bottom of the column. The cold separator 52 can be operated at a pressure between 3MPa (gauge) (435 psig) and 20MPa (gauge) (2,901 psig). The cold separator 52 may also have a reservoir for collecting the aqueous phase. The temperature of the cold hydrocracked stream in cold bottoms line 56 may be the operating temperature of cold separator 52.

The cold vapor hydrocracked stream in cold overhead line 54 is rich in hydrogen. Thus, hydrogen can be recovered from the cold gas stream. The cold gas stream in cold overhead line 54 can be passed through trays or packed recycle absorber 34 wherein the cold gas stream is scrubbed with an absorption liquid, such as an aqueous solution fed through line 35, to remove the acid gas containing hydrogen sulfide and carbon dioxide by absorbing the acid gas into the aqueous solution. Preferred aqueous solutions include lean amines such as alkanolamine, diethanolamine, monoethanolamine, and methyldiethanolamine. Instead of or in addition to the preferred amines, other amines may be used. Lean amine is contacted with the cold vapor stream and absorbs acid gas contaminants such as hydrogen sulfide and carbon dioxide. The resulting "attemperated" cold vapor hydrocracked stream is taken from the top outlet of the recycle absorber 34 in recycle absorber overhead line 36, and the rich amine is taken from the bottom at the bottom outlet of the recycle absorber in recycle absorber bottom line 38. The spent absorption liquid from the bottom of the column may be regenerated and recycled back to (not shown) the recycle absorption column 34 in line 35.

The absorbed hydrogen-rich gas stream is withdrawn from absorber 34 via recycle absorber overhead line 36 and may be compressed in recycle compressor 28 to provide a recycle hydrogen stream in line 22. The recycle hydrogen stream in line 22 can be supplemented with a make-up hydrogen stream in make-up line 24 to provide a hydrogen stream in hydrogen line 20. A portion of the recycle hydrogen stream in line 22 can be directed to the intermediate catalyst bed outlets in the hydroprocessing reactor 30 and the hydrocracking reactor 40 to control the inlet temperature of the subsequent catalyst beds (not shown). The recycle absorber 34 may be operated at a gas inlet temperature between 38 ℃ (100°f) and 66 ℃ (150°f) and an overhead pressure of 3MPa (gauge) (435 psig) to 20MPa (gauge) (2,900 psig).

The hydrocarbon-containing hot liquid hydrocracked stream in the hot bottom line 50 may be considered a hot liquid hydrocracked stream and stripped as a hot hydrocracked liquid stream in the recovery section 16. In one aspect, the hot liquid hydrocracked stream in the hot bottom line 50 may be pressure drop and flashed in the hot flash drum 62 to provide a flash hot vapor hydrocracked stream of light ends in the hot flash overhead line 64 and a flash hot liquid hydrocracked stream in the hot flash bottom line 66. The hot flash drum 62 may be any separator that splits the hot liquid hydrocracked stream into vapor and liquid fractions. The hot flash tank 62 may be in direct downstream communication with the hot bottom line 50 and with the hydrocracking reactor 40. The hot flash tank 62 may operate at the same temperature as the hot separator 46 but at a lower pressure (suitably no more than 3.8MPa (gauge) (550 psig)) between 1.4MPa (gauge) (200 psig) and 6.9MPa (gauge) (1,000 psig). The flash hot liquid hydrocracked stream in hot flash column bottom line 56 may be fractionated in recovery section 16. The temperature of the flash hot liquid hydrocracked stream in the hot flash column bottom line 66 may be the operating temperature of the hot flash tank 62.

In one aspect, the cold liquid hydrocracked stream in cold bottoms line 56 can be considered a cold liquid hydrocracked stream and fractionated in recovery section 16. In another aspect, the cold liquid hydrocracked stream may be pressure dropped and flashed in cold flash drum 68 to separate the cold liquid hydrocracked stream in cold bottom line 56. Cold flash drum 68 may be any separator that splits the hydrocracked stream into vapor and liquid fractions. The cold flash tank 68 may also have a reservoir for collecting the aqueous phase. The cold flash tank 68 may be in direct downstream communication with the cold bottom line 56 of the cold separator 52 and in downstream communication with the hydrocracking reactor 40.

In another aspect, the flash thermally hydrocracked stream in hot flash overhead line 64 may be fractionated into a hydrocracked stream in recovery section 16. In another aspect, the flash hot vapor hydrocracked stream may be cooled and also separated in a cold flash drum 68. The cold flash drum 68 may separate the cold liquid hydrocracked stream in the cold bottoms line 56 and/or the flash hot vapor hydrocracked stream in the hot flash overhead line 64 to provide a flash cold vapor hydrocracked stream in the cold flash overhead line 70 and a flash cold liquid hydrocracked stream in the cold flash bottoms line 72. In one aspect, light gases such as hydrogen sulfide are stripped from the flash cold liquid hydrocracked stream. Thus, the stripper column 80 may be in downstream communication with the cold flash drum 68 and the cold flash bottom line 72. The cold flash tank 68 may be in downstream communication with the cold bottom line 56 of the cold separator 52, the hot flash overhead line 64 of the hot flash tank 62, and the hydrocracking reactor 40. The cold liquid hydrocracked stream in cold bottoms line 56 and the flash hot vapor stream in hot flash overhead line 64 may be passed together or separately into cold flash drum 68. The cold flash tank 68 may operate at the same temperature as the cold separator 52, but typically at a lower pressure of between 1.4MPa (gauge) (200 psig) and 6.9MPa (gauge) (1,000 psig), and preferably between 3.0MPa (gauge) (435 psig) and 3.8MPa (gauge) (550 psig). The flashed aqueous stream may be removed from the storage in the cold flash tank 68. The temperature of the flash cold liquid hydrocracked stream in cold flash bottom line 72 may be the same as the operating temperature of cold flash drum 68. The flash cold vapor hydrocracked stream in cold flash overhead line 70 may contain large amounts of hydrogen that may be further recovered.

Recovery section 16 may include stripping column 80, product fractionation column 140, light fractionation column 160, sponge absorption column 180, and heavy fractionation column 200. Stripper 80 may be in downstream communication with a bottom line in separation section 14 to strip volatiles from the hydrocracked stream. For example, the stripper column 80 may be in downstream communication with the hot bottoms line 50, the hot flash bottoms line 66, the cold bottoms line 56, and/or the cold flash bottoms line 72. In one aspect, the stripper 80 can be a vessel containing a cold stripper 82 and a hot stripper 86 having at least one wall separating each of the strippers 82, 86 from the other. The cold stripper 82 may be in downstream communication with the hydrocracking reactor 40, the cold bottoms line 56, and in one aspect, the cold flash bottoms line 72 for stripping a cold hydrocracked liquid stream, which may be a flash cold hydrocracked liquid stream. Cold stripper 82 may be in downstream communication with hot overhead line 48 and hot flash overhead line 64. The hot stripper 86 may be in downstream communication with the hydrocracking reactor 40, the hot bottoms line 50, and in one aspect, with the hot flash bottoms line 72 for stripping a hot liquid hydrocracked stream that is at least 25 ℃, preferably at least 50 ℃, hotter than the cold liquid hydrocracked stream. In one aspect, the cold liquid hydrocracked stream may be a flash cold liquid hydrocracked stream in a cold flash column bottom line 72.

Stripping columns 82 and 86 operate at high pressure to maintain C in the stripped streams, respectively ₅₊ And C ₆₊ Hydrocarbons, and will mostly C _4- And hydrogen sulfide and other acid gases are stripped overhead. The flashed cold liquid hydrocracked stream in cold flash column bottom line 72 may be considered a cold liquid hydrocracked stream, optionally heated, mixed with an LPG rich absorbent stream in absorber column bottom line 184, and fed to cold stripper 82 at an inlet which may be in the upper half of the column. The cold liquid hydrocracked stream, which may be a flash cold liquid hydrocracked stream, may be stripped in cold stripper 82, which includes at least a portion of the hydrocracked stream in hydrocracking line 44 to provide C in a cold stripper overhead line 88 extending from the top of the cold stripper _4- A cold stripper overhead stream of hydrocarbons, hydrogen sulfide, and other gases and a cold stripped stream is provided in a cold stripper line 98 from the separation section 14. A stripping condenser 91 may be in downstream communication with the stripping overhead line 88. The stripping receiver 92 may be in downstream communication with a stripping condenser 91. The cold stripper overhead stream may be condensed in a stripping condenser 91 and separated in a stripping receiver 92. The stripping receiver overhead line 94 from receiver 92 carries a vapor stripper overhead stream comprising LPG and light gases. The unsteady liquid naphtha from the bottom of receiver 92 in stripping receiver bottoms line 93 extending from the bottom of the stripping receiver may be refluxed to the cold stripper 82 and a liquid stripper overhead stream, which may be fed in liquid stripper overhead line 96 to a light fractionation feed inlet 96i of light fractionation column 160. The sour water stream may be collected from a storage tank of overhead receiver 92. Light fractionation column 160 can be in downstream communication with stripping receiver bottom line 93 and liquid stripping overhead line 96.

The cold stripper 82 can operate at a column bottom temperature of between 149 ℃ (300°f) and 288 ℃ (550°f), preferably no more than 260 ℃ (500°f), and an overhead pressure of 0.35MPa (gauge) (50 psig), preferably no less than 0.70MPa (gauge) (100 psig) to no more than 2.0MPa (gauge) (290 psig). The temperature in the overhead receiver 92 is in the range of 38 ℃ (100°f) to 66 ℃ (150°f) and the pressure is substantially the same as or lower than the overhead pressure of the cold stripper 82.

The cold stripper 82 may use an inert gas medium such as steam for the stripping medium and/or heat input to the column. In one embodiment, the cold reboiled stripped stream taken from the bottom 83 of the cold stripper 82 in a cold reboiling stripped line 97 extending from the bottom 83 of the cold stripper 82 or the cold stripped stream taken from the bottom 83 of the cold stripper 82 in a cold stripped line 98 extending from the bottom 83 of the cold stripper 82 may be boiled in reboiler 95 and returned to the cold stripper 82 to provide heat to the column 82. The bottom 83 of the cold stripper 82 is located below the lowest tray in the column. This is an alternative to feeding an inert gas medium stream such as steam to the cold stripper 82, which avoids the dew point problem in the overhead and avoids the additional equipment required for steam transport and water recovery. Hot oil may be used to heat reboiler 95.

The net cold stripped stream in net cold stripped line 99 may comprise predominantly C in the cold liquid hydrocracked stream fed to cold stripper 82 and in the hydrocracked stream in hydrocracking line 44 ₅₊ And (3) hydrocarbons. In one embodiment, the net cold stripped stream in the net cold stripped line 99 can be split into aliquot portions including the fractionated feed cold stripped stream in the fractionated feed cold stripped line 126 and the absorbent stream in the absorbent line 106. Fractionation feed cold stripping tubeThe fractionated feed cold stripped stream in line 126 can be cooled by heat exchange in a light heat exchanger 129 with the light reboiling stream in light reboiling line 128 and fed to product fractionation column 140.

Product fractionation column 140 can be in downstream communication with cold stripper line 98 of cold stripper column 82 and stripper column 80. In one embodiment, the entire cold stripped stream in the net cold stripper line 99 can be fed to a product fractionation column. In another embodiment, the entire aliquot portion of the fractionation feed cold stripping line 126 comprising the fractionation feed cold stripping stream may be fed to the product fractionation column 140. In one aspect, the product fractionation column 140 can include more than one fractionation column. The product fractionation column 140 may be in downstream communication with one, some, or all of the hot separator 46, the cold separator 52, the hot flash tank 62, and the cold flash tank 68.

The flash hot liquid hydrocracked stream in flash hot bottom line 66 may be considered a hot liquid hydrocracked stream and stripped in hot stripper 86 to provide C in hot stripper overhead line 100 ₅ A hot stripper overhead stream of hydrocarbons, hydrogen sulfide and other gases, and a hot stripped stream is provided in a hot stripper line 102 from the separation section 14. Overhead line 100 may be condensed and a portion refluxed to hot stripper 86. However, in the embodiment of this figure, the hot stripped stream from the top of hot stripper 86 in hot stripper overhead line 100 may be transferred directly to cold stripper 82 on the one hand without first condensing or refluxing. A hot stripper overhead line 100 may extend from the overhead 85 of the hot stripper 86 above the last tray in the hot stripper. The cold stripper may be in downstream communication with the hot stripper overhead line 100. The inlet of the cold flash bottoms line 72 carrying the flash cold liquid hydrocracked stream may be at a higher elevation than the inlet of the overhead line 100, or they may be mixed and fed to the same inlet of the cold stripper 82. The thermal stripper 86 may be operated with a column bottom temperature between 160 ℃ (320F) and 360 ℃ (680°f) and an overhead pressure of 0.35MPa (gauge) (50 psig), preferably 0.70MPa (gauge) (100 psig) to 2.0MPa (gauge) (292 psig). The stripper is operated at higher pressure to optimize LPG and LN recovery.

The reboiled hot stripped stream taken from the bottom 87 of the hot stripper 86 in a hot reboiling stripping line 103 extending from the bottom 87 of the hot stripper or the hot stripped stream taken from the bottom 87 of the hot stripper 86 in a hot stripping line 102 extending from the bottom 87 of the hot stripper can be boiled in reboiler 105 and returned to the hot stripper 86 to provide heat to the column. Reboiler 105 can be a fired heater in downstream communication with reboiling hot stripping line 103 and/or hot stripping line 102 extending from bottom 87 of hot stripper 86. The bottom 87 of the thermal stripper is located below the lowest tray in the column. This is an alternative to feeding a hot stripping medium stream such as steam to the hot stripper 86 which avoids the dew point problem in the overhead and avoids the additional equipment required for steam delivery and water recovery. The hot oil stream can alternatively be used in a heat exchanger to reboil the reboil stream in reboil hot stripper line 103. The hot stripped stream in hot stripping line 102 (which may be the net hot stripped stream if the reboiled stream in reboiling hot stripping line 103 is taken from the hot stripped stream) may comprise predominantly C in the hot liquid hydrocracked stream fed to hot stripper 86 ₆₊ Naphtha. The hot stripped stream in hot stripping line 102 may comprise primarily C from the hydrocracked stream in hydrocracking line 44 ₆₊ A substance.

At least a portion of the hot stripped stream in hot stripped line 102 can be fed to product fractionation column 140. Thus, the product fractionation column 140 can be in downstream communication with the hot stripping line 102 of the hot stripping column 86. The hot liquid hydrotreated stream in hot stripper line 102 can be at a hotter temperature than the cold stripped stream in cold stripper line 98.

In another aspect, the hot stripped stream in hot stripped line 102 is hot enough to exchange heat with the cold reboiled stream in cold reboiled stripped line 97 and boil it to the reboiling temperature in heat exchanger 95. The hot stripped stream will still be at a sufficient temperature to enter the product fractionation column 140 without heating. Heat exchanger 95 may be an indirect heat exchanger and have one side in downstream communication with hot stripping line 102 and/or reboiling hot stripping line 103 extending from bottom 87 of hot stripper 86 and another side in downstream communication with cold stripping line 98 and/or cold reboiling stripping line 97 extending from bottom 83 of cold stripper 82. After cooling in heat exchanger 95, the hot stripped stream in hot stripper line 102 may be fed to product fractionation column 140. Alternatively, the cold stripped stream may be boiled in heat exchanger 95 by heat exchange with hot oil or by hydrocracking the stream in hydrocracking line 44.

Product fractionation column 140 can be in downstream communication with hot stripper column 86 to separate the hot stripped stream into product streams. Even though the hot stripped stream may have been cooled in heat exchanger 95, it is not further heated in the way to product fractionation column 140. Thus, the hot stripped stream is withdrawn from hot stripper 86 at a temperature that is not less than the temperature at which it is fed to product fractionation column 140. The cold stripped stream is not further heated along the route to the product fractionation column 140. The cold stripped stream may be withdrawn from cold stripper 82 at a temperature that is also not less than the temperature at which it is fed to product fractionation column 140.

The product fractionation column 140 can include a prefractionation column 142. In one embodiment, prefractionation column 142 is located outside of product fractionation column 140. The portion of the product fractionation column 140 that does not contain the prefractionation column 142 is referred to as the product portion 150 of the product fractionation column 140. In one aspect, the fractionation feed cold stripped stream in the fractionation feed cold stripped line 126 can be fed to the prefractionator 142 through the fractionation feed cold stripped inlet 126 i. In one embodiment, the entire aliquot portion comprising the fractionated feed cold stripped stream in the fractionated feed cold stripped line 126 may be fed to the prefractionation column 142 of the product fractionation column 140. Prefractionation column 142 may include a column that may be in downstream communication or directly downstream communication with a cold bottom line 98 extending from the bottom 83 of cold stripper column 82. Prefractionation column 142 may prefractionate the fractionation feed cold stripped stream in fractionation feed cold stripped line 126 to provide a prefractionation overhead stream in prefractionation overhead line 132 and a prefractionation bottoms stream in prefractionation bottom line 134.

The hot stripped stream in hot stripping line 102 may feed or bypass prefractionator 142. In one aspect, the hot stripped stream in hot stripping line 102 can be fed to prefractionator 142 through hot stripping inlet 102 i. In this embodiment, the entire hot stripped stream in hot stripping line 102 is fed to prefractionator 142 of product fractionation column 140. Prefractionation column 142 may include a column that may be in downstream communication with or directly downstream of a hot bottom line 102 extending from the bottom 87 of hot stripper 86. In one aspect, both the fractionation feed cold stripped stream in the fractionation feed cold stripped line 126 and the hot stripped stream in the hot stripped line 102 can be fed to the prefractionator 142. Prefractionation column 142 may include a column that may be in downstream communication with a hot bottom line 102 extending from the bottom 87 of hot stripper column 86 and a cold bottom line 98 extending from the bottom 83 of cold stripper column 82. Prefractionation column 142 may prefractionate the split feed cold and hot stripped streams to provide a prefractionation overhead stream in prefractionation overhead line 132 and a prefractionation bottoms stream in prefractionation bottom line 134. The fractionation feed cold stripping inlet 126i of the fractionation feed cold stripping line 126 for transporting the fractionation column feed cold stripping stream may be located at a higher elevation than the hot bottom inlet 102i of the hot stripping stream for transport in the hot bottom line 102.

Prefractionation overhead line 132 conveys a prefractionation overhead stream, which is vapor, from top outlet 132o of prefractionation column 142 to vapor feed upper inlet 132i, into the vapor space above vapor feed tray 133 in product portion 150 of product fractionation column 140. Prefractionation bottoms line 134 passes prefractionation bottoms stream, which is liquid, from bottom outlet 134o of prefractionation column 142 to liquid feed inlet 134i onto liquid feed trays in product section 150 of product fractionation column 140. Prefractionation column 142 may be a column thermally integrated with product fractionation column 140, so no reboiler or condenser is implemented on prefractionation column 142. Prefractionation column 142 may be a Petlyuk column.

A liquid reflux stream in reflux line 136 is taken from a liquid outlet on the underside of vapor feed tray 133 in product portion 150 of product fractionation column 140 and returned to prefractionator 142. The reflux stream is taken from a liquid outlet on a vapor feed tray 133 below the vapor feed upper inlet 132i for the prefractionation overhead stream to the product portion 150 of the product fractionation column 140. Reflux inlet 136i for reflux line 136 is at a level below top outlet 132o on prefractionator 142. The vapor stripped stream in stripping line 138 is taken from a vapor outlet in the vapor space above liquid feed tray 135 in product portion 150 of product fractionation column 140 and returned to prefractionator 142. The stripped stream is taken from a vapor outlet above the liquid feed inlet 134i of the prefractionated bottoms stream to the product portion 150 of the product fractionation column 140. The stripping inlet 138i for the stripping line 138 is at a higher elevation than the bottom outlet 134o on the prefractionator 140. The product portion 150 of the product fractionation column 140 may be in downstream communication with the top outlet 132o of the prefractionator 142 and the bottom outlet 134o of the prefractionator.

In one embodiment, the hot stripped stream in the hot bottom line 102 may bypass the prefractionator 142 and directly enter the product portion 150 of the product fractionation column 140. In this aspect, the inlet of the heat tower bottom line 102 is located below the liquid feed inlet 134i from the prefractionator 142. In this embodiment, the entire hot stripped stream in hot stripping line 102 is fed to product portion 150 of product fractionation column 140. Thus, the product portion 150 of the product fractionation column 140 can be in direct downstream communication with the hot stripping line 102 of the hot stripper column 86. If hot stripping line 102 first feeds product portion 150 of product fractionation column 140 (prefractionator 142 is in downstream communication therewith), prefractionator 142 may be in indirect communication with hot stripping line 102 downstream of hot stripper column 86.

The product fractionation column 140 separates three product streams including Light Naphtha (LN), heavy Naphtha (HN), and distillate. After prefractionation of at least the fractionated feed cold stripped stream in prefractionation column 142, product fractionation column 140 fractionates the fractionated feed cold stripped stream in fractionated feed cold stripped line 126 and the hot stripped stream in hot stripped line 102 to provide a product overhead stream comprising LN in net product overhead line 146, a product intermediate stream comprising heavy naphtha taken from side outlet 148o in product intermediate line 148, and a net product bottoms stream comprising unconverted oil stream in net product bottom line 156. If the hydrocarbon stream in hydrocarbon line 18 is a vacuum gas oil stream, the unconverted oil stream may be a heavier stream such as vacuum gas oil. Alternatively, if the hydrocarbon stream in hydrocarbon line 18 is a distillate stream, the unconverted oil stream may be a distillate such as diesel and/or kerosene.

The product overhead stream in product overhead line 154 from the product portion of product fractionation column 140 can be cooled to complete condensation to provide a net product overhead stream comprising LN in net product overhead line 146. The reflux portion of the product overhead stream may be refluxed to the product portion 150 of the product fractionation column 140. The net product overhead stream in net product overhead line 146 comprises primarily C in the fractionation column feed cold stripped stream in fractionation column feed cold stripped line 126 and the hot stripped stream in hot stripped line 102 ₅ -C ₆ Naphtha. The product bottoms stream in product bottoms line 152 from the bottom of product portion 150 of product fractionation column 140 can be split between the net product bottoms stream in net product bottoms line 156 and the product boiling stream in product reboiling line 158. The product boiling stream in product reboiling line 158 reboils in a heater that requires external facilities such as a fired heater or hot oil and is returned to the product portion of product fractionation column 140. The intermediate stream taken from side outlet 148o is taken from the side of product portion 150 of product fractionation column 140. The intermediate stream is withdrawn from a side outlet 148o between a vapor feed upper inlet 132i of the prefractionation overhead stream to the product portion 150 of the product fractionation column 140 and a lower liquid inlet 134i of the prefractionation bottoms stream to the product portion of the product fractionation column. An unconverted oil stream comprising distillate or VGO may be taken from the product fractionation bottoms line 152 and provided in recycle oil line 156 to the hydrocracking reactor 40 or to a second hydrocracking reactor for the second stage unit, not shown. In alternative embodiments, an unconverted oil stream may be taken from the product fractionation bottoms line 152 and provided to the heavy fractionation column 200 in the unconverted oil line 156 for further fractionation. The product fractionation column 140 can be operated at a temperature between 204 ℃ (400°f) and 385 ℃ (725°f) and a pressure between 69kPa (absolute) and 414kPa (absolute). Product fractionation column 140 can be operated to minimize energy consumption because good split is achieved in stripping column 80, and because stripping column 80 and product fractionation column 140 are thermally integrated to minimize remixing of light and heavy components.

The net product bottoms stream in net product bottoms line 156 comprises primarily distillate including diesel and/or kerosene or VGO from the hydrocracked stream in hydrocracked line 44. The naphtha split point between the naphtha and distillate can be between 150 ℃ (302°f) and 200 ℃ (392°f). The net product overhead stream in net product overhead line 146 contains more LN than the LN in the product intermediate stream in product intermediate line 148 or the net product bottoms stream in net product bottoms line 156. The fractionation point between LN and HN may be between 77 ℃ (170°f) and 99 ℃ (210°f). The product intermediate stream in product intermediate line 148 contains more HN than the HN in the net product overhead stream in net product overhead line 146 or the net product bottoms stream in net product bottoms line 152. The intermediate stream in intermediate line 148 taken from side outlet 148o contains primarily C from the hydrocracked stream in hydrocracking line 44 ₆ -C ₁₂ A substance.

Using the ASTM D-86 distillation method, if the net product bottoms stream in net product bottoms line 156 comprises VGO, it can have T5 between 165 ℃ (330 DEG F) and 204 ℃ (400 DEG F) and T95 between 480 ℃ (900 DEG F) and 565 ℃ (1,050 DEG F). Using ASTM D-86 distillation methods, if the net product bottoms stream in net product bottoms line 156 comprises a distillate comprising kerosene and/or diesel, it can have T5 between 165 ℃ (330°f) and 204 ℃ (400°f) and T95 between 266 ℃ (510°f) and 371 ℃ (700°f). Using ASTM D-86 distillation methods, the product intermediate stream comprising HN in product intermediate line 148 can have T5 between 65 ℃ (150°f) and 120 ℃ (248°f) and T95 between 154 ℃ (310°f) and 193 ℃ (380°f). The net product overhead stream in the LN-containing net product overhead line 146 can have a T5 between 7 ℃ (45°f) and 40 ℃ (100°f) and a T95 between 50 ℃ (120 ℃) and 82 ℃ (180°f).

Fig. 2 shows an alternative embodiment of the product fractionation column 140' of fig. 1. Many of the elements in fig. 2 have the same configuration as in fig. 1 and have the same reference numerals. Elements in fig. 2 that correspond to elements in fig. 1 but have a different configuration have the same reference numerals as in fig. 1, but are marked with a prime ('). In the embodiment of fig. 2, a prefractionation column 142 'is included in the product fractionation column 140'. The product fractionation column 140 'can include a dividing wall 144 that divides the product fractionation column 140' into a prefractionation column 142 'and a product portion 150'. The top 144t and bottom 144b ends of the dividing wall 144 do not contact the top and bottom of the product fractionation column 140', respectively, and thus material can travel from the prefractionation column 142' to the product section 150' above and below the dividing wall 144, and vice versa. The top end 144t of the dividing wall 144 defines the upper inlet 132' of the prefractionator 142' to the product fractionation column 140', and the bottom end 144b of the dividing wall defines the lower inlet 134' of the prefractionator to the product fractionation column 140 '.

The fractionated feed cold stripped stream in the fractionated feed cold stripped line 126 'may be fed to the prefractionator 142' through the wall 151 'of the product fractionation column 140'. Prefractionation column 142' may be in downstream communication with cold bottom line 98. The fractionation feed cold inlet 126i' for the cold stripped stream in the fractionation feed cold stripping line 126 is located vertically between the top end 144t and the bottom end 144b of the dividing wall 144. Partition wall 144 is interposed between prefractionator 142' and side outlet 148o so the feed material must travel above or below partition wall 144 to exit side outlet 148o in the product intermediate stream in product intermediate line 148. Prefractionation column 142' prefractionates the split feed cold stripped stream to provide a prefractionation overhead stream exiting prefractionation column 142' by rising at top end 144t of dividing wall 144 and a prefractionation bottoms stream exiting prefractionation column 142' by falling at bottom end 144b of dividing wall 144.

The hot stripped stream in hot stripping line 102 'may be fed to prefractionation column 142' through wall 151 'of product fractionation column 140'. Prefractionation column 142 'may be in downstream communication with thermal bottoms line 102'. In this aspect, the fractionation feed cold inlet 126i 'for the cold stripped stream in the fractionation feed cold stripping line 126' and the hot stripped feed inlet 102i 'for the hot stripped stream in the hot stripping line 102' are vertically positioned between the top end 144t and the bottom end 144b of the dividing wall 144. Partition wall 144 is interposed between prefractionator 142' and side outlet 148o so the feed material must travel above or below partition wall 144 to exit side outlet 148o in the product intermediate stream in product intermediate line 148. The prefractionation column 142' prefractionates the hot stripped stream to provide a prefractionation overhead stream exiting the prefractionation column 142' by rising at the top end 144t of the dividing wall 144 and a prefractionation bottoms stream exiting the prefractionation column 142' by falling at the bottom end 144b of the dividing wall 144.

In another aspect, the hot stripped stream in hot stripping line 102 can be fed to product fractionation column 140' to bypass prefractionator 142' by positioning hot stripping feed inlet 102i ' below bottom end 144b of dividing wall 144.

The prefractionation overhead stream, as vapor, rises from prefractionation column 142' through upper inlet 132' to product fractionation column 140' to above the top end 144t of dividing wall 144. The upper inlet 132 'may be defined by a chimney in the upper tray 133' above the dividing wall 144. The prefractionation bottoms stream as a liquid descends from prefractionation column 142 'through bottom inlet 134' to product fractionation column 140 'to below bottom end 144b of dividing wall 144 in product fractionation column 140'. Prefractionation column 142' is thermally integrated with product fractionation column 140', so no additional reboiler or condenser is implemented on prefractionation column 142'. The product fractionation column 140' can be a divided wall column.

The liquid reflux stream from the product fractionation column 140' above the top end 144t of the dividing wall 144 can be refluxed back to the prefractionator 142' and to the product portion 150' below the top end 144 t. Reflux outlet 136 'from product fractionation column 140' to prefractionation column 142 'may be a downcomer in upper tray 133' or a liquid collection well that distributes liquid below the upper tray at a lower elevation than upper inlet 132 'to prefractionation column 142'. The vapor stripped stream from the product fractionation column 140' below the bottom end 144b of the dividing wall 144 can be returned to the prefractionator 142' and to the product portion 150' below the bottom end 144 b. The stripping outlet from the product fractionation column 140' back to the prefractionation column 142' may be the same as the bottom inlet 134 '. The product fractionation column 140 'may be in downstream communication with an upper inlet 132' from the prefractionator 140 'and a lower inlet 134' from the prefractionator.

The product fractionation column 140' separates three product streams including Light Naphtha (LN), heavy Naphtha (HN), and distillate. The product fractionation column 140' fractionates the fractionated feed cold stripped stream in the fractionated feed cold stripped line 126' after prefractionation in prefractionation column 142' and possibly the hot stripped stream in the hot stripped line 102' after prefractionation in prefractionation column 142' to provide a product overhead stream comprising LN in the net product overhead line 146, a product intermediate stream comprising heavy naphtha obtained from side outlet 148o in product intermediate line 148o, and a net product bottoms stream comprising distillates such as diesel and/or kerosene and/or VGO in net product bottom line 156. The product overhead stream in product overhead line 154 from product fractionation column 140' can be cooled to complete condensation to provide a net product overhead stream comprising LN in net product overhead line 146. The reflux portion of the product overhead stream may be refluxed to the product fractionation column 140'. The product bottoms stream in product bottoms line 152 from the bottom of product fractionation column 140' can be split between the net product bottoms stream in net product bottoms line 156 and the product boiling stream in product reboiling line 158. The product boiling stream in product reboiling line 158 reboils in a heater that requires external facilities such as a fired heater and is returned to product fractionation column 140'. The intermediate stream taken from side outlet 148o is taken from the side of product fractionation column 140'. The intermediate stream exits from a side outlet 148o between an upper inlet 132' to the prefractionation overhead stream of the product fractionation column 140' and a lower inlet 134' to the prefractionation bottoms stream of the product fractionation column. The product fractionation column 140' can be operated at a temperature between 204 ℃ (400°f) and 385 ℃ (725°f) and a pressure between 103kPa (gauge) and 276kPa (gauge). The remainder of the embodiment of fig. 2 is constructed and operates as described with respect to fig. 1.

The liquid stripper overhead stream in liquid stripper overhead line 96 contains valuable hydrocarbons that can still be recovered. Thus, it may be sent to the light fractionation column 160 for fractionation to recover LPG and light hydrocarbons in the LN range. The light fractionation column 160 can be in downstream communication with the cold stripper overhead line 88 of the cold stripper column 82.

The liquid stripped stream in liquid stripping overhead line 96 can be heated by heat exchange in recovery section 16 to effect light fractionation. A light intermediate heat exchanger 125 having one side in downstream communication with the light fractionation intermediate line 166 and the other side in downstream communication with the liquid stripping overhead line 96 transfers heat from the light fractionation intermediate stream to the liquid stripping overhead stream. A product intermediate heat exchanger 145 having one side in downstream communication with the product fractionation intermediate line 148 and the other side in downstream communication with the liquid stripping overhead line 96 (in downstream communication with the light intermediate heat exchanger 125) transfers heat from the product fractionation intermediate stream to the primary heated liquid stripping overhead stream. A light bottoms heat exchanger 165, having one side in downstream communication with the net light fractionation bottoms line 172 and the other side in downstream communication with the liquid stripping overhead line 96 (in downstream communication with the product intermediate heat exchanger 145), transfers heat from the net light fractionation bottoms stream to the twice heated liquid stripping overhead stream. The liquid stripper overhead stream in liquid stripper overhead line 96 is heated only by heat exchange with the hotter stream in recovery section 16 to be sufficiently heated for fractionation in light fractionation column 160.

The light ends fractionation column 160 fractionates the liquid stripper overhead stream in liquid stripper overhead line 96 fed through light ends feed inlet 96i to provide a light fractionation overhead stream as vapor in a light overhead line 162 extending from the top of the light fractionation column, a light fractionation intermediate stream in a light fractionation intermediate line 166 extending from a side 161 of the light fractionation column, and a light fractionation bottoms stream in a light fractionation bottoms line 164 extending from the bottom of the light fractionation column. Light fractionation of the liquid stripper overhead stream in liquid stripper overhead line 96 into three of the foregoing streams is accomplished in a single light fractionation column 160.

A light condenser 163 can be in downstream communication with the light overhead line 162 to at least partially condense the light fractionation overhead stream therein. Light overhead receiver 168 may be in downstream communication with light condenser 163 and light overhead line 162. The light fractionation overhead stream in light fractionation column overhead line 162 can be at least partially condensed and separated in light overhead receiver 168 into a liquid light fractionation overhead stream for reflux to column 160 and a vapor light fractionation overhead stream in light receiver overhead line 170 comprising predominantly dry gas, the dry gas being C _2- And lighter gases, including non-organic gases.

In one embodiment, the light fractionation column 160 can be a debutanizer to fractionate the liquid stripped stream in the liquid cold stripping overhead line 96 to contain predominantly C ₅₊ A light bottoms stream of hydrocarbons. A light fractionation bottoms stream can be withdrawn from the bottom of light fractionation column 160 in light bottom line 164. A reboiled stream taken in light bottoms line 164 from the light bottoms stream or from the bottom of light fractionation column 160 can be boiled in light reboiling line 128 and sent back to the light fractionation column to provide heat to the column. This is an alternative to feeding a stream of a hot inert medium, such as steam, to column 160, which avoids dew point problems in the overhead and avoids additional equipment required for steam transport and water recovery. The light reboiling stream in light reboiling line 128 can be heated by heat exchange in light heat exchanger 129 with the fractionation feed cold stripping stream in fractionation feed cold stripping line 126, which is hotter than the light reboiling stream in light reboiling line 128, and fed back to light fractionation column 160.

Boiling C in the range of light naphtha ₅ -C ₆ In hydrocarbon embodiments, the net light bottoms stream is withdrawn in net light bottoms line 172. The fractionation point between LPG and LN may be between 4 ℃ (40 °F) and 38 ℃ (100°f). The net light bottoms stream in net light bottoms line 172 comprising LN can have T5 between 7 ℃ (45°f) and 40 ℃ (104°f) and T95 between 50 ℃ (120 ℃) and 82 ℃ (180°f). The net light ends bottoms stream in net light ends fractionation bottoms line 172 contains primarily C from the hydrocracked stream in hydrocracking line 44 and the fractionated feed cold stripped stream in fractionation feed cold stripped line 126 ₅ -C ₆ Hydrocarbons, also known as LN, do not require an additional naphtha splitter. The net light bottoms stream in net light bottoms line 172 can be heat exchanged in light bottoms heat exchanger 165 to heat the liquid stripped stream in liquid cold stripper line 96 before it enters light fractionation column 160. The cooled net light bottoms stream in net light bottoms line 172 can be mixed with the net product overhead stream comprising LN in net product overhead line 146 to provide the LN product stream in LN product line 174. A majority of the LN in the hydrocracked product stream in hydrocracked product line 44 is taken in the LN product stream in LN product line 174. The net LN product stream in net LN product line 174 can have T5 between 7 ℃ (45°f) and 40 ℃ (104°f) and T95 between 50 ℃ (120 ℃) and 82 ℃ (180°f).

A light fractionation intermediate stream can be taken in a light fractionation intermediate line 166 from an intermediate side outlet 166o of a side 161 of the light fractionation column 160. A light fractionation feed inlet 96i to the light fractionation column 160 in downstream communication with the liquid stripping overhead line 96 is located at a level below the mid-side outlet 166o of the light fractionation mid-line 166. A majority of the LPG from the hydrocracked stream in the hydrocracked line 44 is in the light fractionation intermediate stream in the light fractionation intermediate line 166. The light fractionation intermediate stream in light fractionation intermediate line 166 is heat exchanged with the liquid cold stripped stream in liquid stripping overhead line 96 and provides an LPG product stream. The LPG product stream in the light fractionation intermediate line 166 that includes LPG can include between 10 and 30 mole% propane and between 60 and 90 mole% butane.

The light ends fractionation column 160 can be operated with a column bottom temperature between 105 ℃ (225°f) and 200 ℃ (392°f), preferably between 160 ℃ (320°f) and 200 ℃ (392°f), and an overhead pressure of 689kPa (gauge) (100 psig) to 2.4MPa (gauge) (350 psig), preferably 1MPa (gauge) (150 psig) to 2MPa (gauge) (300 psig). By using a single three-product debutanizer light fractionation column 160, the deethanizer, including the accompanying reboiler and condenser, is omitted, resulting in less condenser duty.

The vapor stripped stream in stripping receiver overhead line 94 from stripping receiver 92 may comprise recoverable LPG hydrocarbons. The vapor stripper overhead stream comprising LPG hydrocarbons and dry gas may be sent to a sponge absorber 180 to recover LPG and naphtha hydrocarbons. In one aspect, the entire vapor stripper overhead stream in stripping receiver overhead line 94 is sent to sponge absorber 180 to absorb LPG from the entire vapor stripper overhead stream.

The vapor light fractionation overhead stream in light receiver overhead line 170 from light receiver 168 can comprise recoverable LPG hydrocarbons. The vapor light fractionation overhead stream comprising LPG hydrocarbons and dry gas can be sent to a sponge absorber 180 to recover LPG and naphtha hydrocarbons. In one aspect, the entire vapor light fractionation overhead stream in the light receiver overhead line 170 is sent to a sponge absorber 180 to absorb LPG from the entire vapor stripper overhead stream.

A lean absorption stream is obtained in lean absorption line 106 from the net cold stripped stream in net cold stripped line 99. In one aspect, the lean absorbent stream in lean absorbent line 106 is an aliquot portion of the net cold stripped stream in net cold stripped line 99. In one aspect, the fractionated feed cold stripped stream in the fractionated feed cold stripped line 126 can also be taken as an aliquot portion from the net cold stripped stream in the net cold stripped line 99. The lean absorbent stream in lean absorbent line 106 is cooled by heat exchange with the rich absorbent stream in absorber bottoms line 184 and is further cooled before it is fed to sponge absorber 180. Because cold stripper 82 uses reboiler 95 instead of steam stripping to heat the column, no equipment such as a coalescer is required to remove water from the lean absorbent stream in absorption line 106. Thus, there is no aqueous phase in the lean absorbent stream due to the lack of added steam during stripping with the reboiling column. The sponge absorber 180 is in direct downstream communication with the cold stripper 82 and, in particular, with the cold stripper line 98.

The multi-tray sponge absorber 180 may include a gas inlet at a tray location near the bottom of the sponge absorber 180. The sponge absorber 180 receives the vapor stripped stream in the stripping receiver overhead line 94 at a gas inlet via sponge absorber feed line 178. The sponge absorber 180 may be in direct downstream communication with the cold stripper 82 and, in particular, with the stripping receiver overhead line 94.

The sponge absorber 180 may also receive a vapor light fractionation overhead stream in the light receiver overhead line 170 at a gas inlet via a sponge absorber feed line 178. The sponge absorber 180 may be in direct downstream communication with the light fractionation column 160, and in particular with the net light receiver overhead line 170. In one aspect, the sponge absorber feed line 178 can feed the vapor light fractionation overhead stream from the light receiver overhead line 170 and the vapor stripper overhead stream from the stripping receiver overhead line 94 together to the sponge absorber 180.

The lean absorbent stream in lean absorbent line 106 may be fed to the sponge absorber 180 through an absorbent inlet. In the sponge absorber 180, the lean absorbent stream is countercurrently contacted with the vapor stripping stream. The sponge absorbent absorbs hydrocarbons from the vapor stripped stream. In the sponge absorber 180, the lean absorbent stream and the vapor light fractionation overhead stream are countercurrently contacted. The sponge absorber absorbs hydrocarbons from the vapor light fractionation overhead stream. The sponge absorber may absorb hydrocarbons from the vapor light fractionation overhead stream and the vapor stripping overhead stream together.

The hydrocarbons absorbed by the sponge absorbent include some methane and ethane and most of the LPG, C in the cold stripper overhead and/or light fractionation overhead ₃ And C ₄ Hydrocarbons and any C ₅ And C ₆₊ Light naphtha hydrocarbons. The sponge absorber 180 is at a temperature of 34 ℃ (93°f) to 60 ℃ (140°f) and is in communication with the stripping receiver 92 and/or light endsThe receiver 168 operates at substantially the same or lower pressure, thereby reducing friction losses. The sponge absorption offgas stream exits the top of sponge absorber 180 at the top outlet via sponge absorber overhead line 182. A portion of the sponge absorption offgas stream in sponge absorber overhead line 182 may be sent to a hydrogen recovery unit for hydrogen recovery, not shown. The LPG hydrocarbon-rich absorption stream exits the bottom of the sponge absorber 180 at a bottom outlet in the rich absorber bottom line 184 and may be recycled to the stripper 80, and specifically to the cold stripper 82. The rich absorption stream in the absorber bottoms line 184 can be heat exchanged with the lean absorption stream in the lean absorption line 106 to cool the lean absorption stream and heat the rich absorption stream. The cold stripper 82 may be in downstream communication with the sponge absorber 180 via an absorber bottom line 184.

In one embodiment, particularly when the feed stream in hydrocarbon line 18 is a heavy feed such as VGO, the net product bottoms stream in net product bottoms line 156 can be passed to a heavy fractionation column 200, which can be in downstream communication with product fractionation column 140 (specifically, product bottoms line 152) for fractionating the net product bottoms stream in net product bottoms line 156 into a product stream. In this embodiment, a majority of the diesel in the product bottoms stream in product bottoms line 152 that is fed to product fractionation column 140 is withdrawn from product fractionation column 140. An inert gas stripping stream such as steam from stripping line 202 may be fed to the bottom 201 of the heavy fractionation column 200 to provide heat to the heavy fractionation column and strip lighter components from the heavier components. The heavy fractionation column 200 can be in downstream communication with a stripping line 202.

The heavy fractionation column 200 produces a heavy intermediate stream in a heavy intermediate line 210 from a side outlet 210 in a side 203 of the heavy fractionation column 200. Using the TBP distillation process, the heavy fractionation column is operated to produce a heavy intermediate stream comprising diesel having a TBP initiation point between 125 ℃ (257°f) and 175 ℃ (347°f), or between 215 ℃ (419°f) and 260 ℃ (500°f if an upper intermediate stream is employed), and a T95 between 343 ℃ (650°f) and 399 ℃ (750°f). Most of the diesel from the hydrocracked stream in hydrocracking line 44 is discharged in the heavy intermediate stream in heavy intermediate line 210. We have found that the heavy intermediate stream is ready for use in a diesel pool without any side stripping of volatile hydrocarbons, water or gases. The heavy intermediate stream contains no more than 100wppm water, and preferably no more than 50wppm water, and has a flash point between 38 ℃ (100°f) and 70 ℃ (158°f), preferably no more than 60 ℃ (140°f).

The heavy fractionation column 200 can produce an upper intermediate stream in an upper intermediate line 230 from a side outlet in a side 203 of the heavy fractionation column 200. The heavy fractionation column can be operated to produce a light distillate stream comprising kerosene having a TBP initiation point of between 125 ℃ (257°f) and 175 ℃ (347°f), preferably between 150 ℃ (302°f) and 165 ℃ (329°f), and a TBP endpoint of between 215 ℃ (419°f) and 260 ℃ (500°f). Most of the kerosene from the hydrocracked stream in hydrocracking line 44 is discharged in the upper intermediate stream in upper intermediate line 230. We have found that the upper intermediate stream is ready for use in a kerosene pond without any side stripping of volatile hydrocarbons, water or gases. The upper intermediate stream contains no more than 100wppm water, and preferably no more than 50wppm water, and has a flash point between 38 ℃ (100°f) and 60 ℃ (140°f).

Unconverted oil stream in heavy bottoms line 206 may be recovered from the bottom of heavy fractionation column 200. The unconverted oil stream has a boiling point above the diesel fractionation point and may be recycled to the hydrocracking reactor 40 or to a second hydrocracking reactor (not shown) in a two-stage hydrocracking unit. Unconverted oil streams may also be used as fluid catalytic cracking feeds or for lubricant production. In addition, the heavy polynuclear aromatic stream concentrated in the heavy polynuclear aromatic compounds may be removed from the unconverted oil stream in the heavy bottoms line 206 before the unconverted oil stream is further hydrocracked.

The heavy fractionation column 200 is operated at subatmospheric vacuum overhead. The overhead stream in overhead line 204 can be fed to a vacuum generation device 214 in downstream communication with the heavy overhead line 204. The vacuum generating device 214 may include an ejector or vacuum pump in communication with an inert gas stream 216 (such as steam) that draws a vacuum on the overhead stream in the overhead line 204. The condensed hydrocarbon stream in line 218 from the vacuum generating device 214 can be returned to the heavy fractionation column 200. The condensed aqueous stream may also be removed from the vacuum generating device in line 220. A vapor stream, which may include hydrocarbon vapors, may be removed from the vapor generation device in line 222.

Heat can be removed from the heavy fractionation column 200 by cooling a portion of the upper intermediate stream in line 230 and/or the heavy intermediate stream in line 210 and returning the cooled stream to the column. The heavy fractionation column 200 may be operated at a column bottom temperature of between 260 ℃ (500°f) and 370 ℃ (700°f), preferably 300 ℃ (570°f), and at a column top pressure of between 27kPa (absolute) (3.9 psia) and 67kPa (absolute) (9.7 psia), and preferably 40kPa (absolute) (5.8 psia) to 53kPa (absolute) (7.7 psia). A portion of the unconverted oil in heavy bottoms line 206 may be reboiled and returned to heavy fractionation column 200 instead of using steam stripping to add heat to the heavy fractionation column.

It is contemplated that all columns are reboiled with a hot oil system, except for the sponge absorber 180, which is cold operated to maximize LPG recovery.

Any of the above lines, units, separators, towers, ambient, zones or the like may be equipped with one or more monitoring components, including sensors, measurement devices, data capture devices, or data transmission devices. The signals, process or state measurements and data from the monitoring components can be used to monitor conditions in, around and associated with the process equipment. The signals, measurements, and/or data generated or recorded by the monitoring component may be collected, processed, and/or transmitted over one or more networks or connections, which may be private or public, general purpose or special purpose, direct or indirect, wired or wireless, encrypted or unencrypted, and/or combinations thereof; the description is not intended to be limiting in this respect.

Signals, measurements, and/or data generated or recorded by the monitoring component may be transmitted to one or more computing devices or systems. The computing device or system may include at least one processor and memory storing computer-readable instructions that, when executed by the at least one processor, cause the one or more computing devices to perform a process that may include one or more steps. For example, one or more computing devices may be configured to receive data from one or more monitoring components related to at least one piece of equipment associated with the process. One or more computing devices or systems may be configured to analyze the data. Based on the data analysis, the one or more computing devices or systems may be configured to determine one or more recommended adjustments to one or more parameters of one or more processes described herein. The one or more computing devices or systems may be configured to transmit encrypted or unencrypted data including one or more recommended adjustments to one or more parameters of one or more processes described herein.

Examples

Example 1

A mixture of straight run gas oil and coker gas oil with a TBP T5 of 176 ℃ and T90 of 357 ℃ was simulated in a two-stage hydrocracking unit, wherein fractionated diesel range material was recycled to the second stage hydrocracking reactor. The use of a cold stripper and a hot stripper with heat integration between the column reboilers as described above results in the elimination of 5,397kg/hr (5.95 t/hr) steam usage and a heater load savings of 29.5kJ/hr (28 Mbtu/hr) relative to a single stripper. In addition, less material is lifted to the stripping overhead, requiring less condenser loading in the overhead, and less loading on the downstream light fractionation column to remove heavier materials designed for exiting in the stripping bottoms stream. The stripping stream from the bottom of the stripping column is at a higher temperature, requiring less heater duty in the product fractionation column.

Example 2

The simulation of example 1 was further evaluated by comparing the product fractionation using a conventional product fractionation with the product fractionation using a prefractionator Petlyuk column. We found that the product fractionation column with a prefractionator uses 16,964kg/hr (18.7 t/hr) less steam and 2.5kJ/hr (2.4 MBtu/hr) less load. The prefractionator also enables higher column bottom temperatures, which results in capital savings and lower condenser loading in the reactor section, less sour water, and more smaller diameter trays. Further, by taking the middle fraction of the heavy naphtha and taking the overhead fraction of the light naphtha, the naphtha splitter column can be omitted.

Example 3

The simulations of example 1 and example 2 were further evaluated by comparing the use of a conventional deethanizer/debutanizer combination with a single light fractionation column providing three product fractions. We have found that the light fractionation column that provides the middle light fraction of LPG uses a load of 1.7kJ/hr less (1.6 MBtu/hr). The light fractionation column uses one column, one reboiler, and one condenser instead of two or more trays, but with less condenser duty.

Example 4

The simulations of example 1 and example 2 were further evaluated by adding a heavy fractionation column operated at vacuum pressure and steam stripping to obtain unconverted oil boiling in the VGO range from the product fractionation column bottoms provided by the reboiled product fractionation column. We have found that a heavy fractionation column that provides an upper middle stream of kerosene and a heavy middle fraction of diesel uses 28% less heater duty and 87% less steam.

Detailed description of the preferred embodiments

While the following is described in conjunction with specific embodiments, it is to be understood that the description is intended to illustrate and not limit the scope of the foregoing description and the appended claims.

A first embodiment of the invention is a process for recovering a hydrocracked product comprising hydrocracking a feed stream with a hydrogen stream over a hydrocracking catalyst in a hydrocracking reactor to provide a hydrocracked stream; separating the hydrocracked stream into a hot liquid hydrocracked stream and a cold liquid hydrocracked stream; stripping the hot liquid hydrocracked stream in a hot stripper column to provide a hot stripped stream; stripping the cold liquid hydrocracked stream in a cold stripper column to provide a cold stripped stream; feeding the cold stripped stream and the hot stripped stream to a product fractionation column; and passing the product bottoms stream to a heavy fractionation column. Embodiments of the invention are one, any or all of prior embodiments in this paragraph up through the first embodiment in this paragraph further comprising operating the heavy fractionation column under vacuum. An embodiment of the invention is one, any or all of prior embodiments in this paragraph up through the first embodiment in this paragraph further comprising withdrawing a heavy distillate stream comprising diesel from the heavy fractionation column. An embodiment of the invention is one, any or all of prior embodiments in this paragraph up through the first embodiment in this paragraph further comprising withdrawing a majority of the diesel in the product bottoms stream that is fed to the product fractionation column. An embodiment of the invention is one, any or all of prior embodiments in this paragraph up through the first embodiment in this paragraph further comprising discharging a majority of the diesel from the hydrocracked stream in the heavy distillate stream. An embodiment of the invention is one, any or all of prior embodiments in this paragraph up through the first embodiment in this paragraph further comprising reboiling the product reboiling stream from the bottom of the product fractionation column and returning the product reboiling stream to the bottom of the product fractionation column. Embodiments of the invention are one, any or all of prior embodiments in this paragraph up through the first embodiment in this paragraph further comprising feeding the gaseous stripping stream to a bottom of the heavy fractionation column. An embodiment of the invention is one, any or all of prior embodiments in this paragraph up through the first embodiment in this paragraph further comprising feeding an entire aliquot portion of the cold stripped stream to the product fractionation column. Embodiments of the invention are one, any or all of prior embodiments in this paragraph up through the first embodiment in this paragraph further comprising feeding the entire hot stripped stream to the product fractionation column. Embodiments of the invention are one, any or all of prior embodiments in this paragraph up through the first embodiment in this paragraph, comprising passing the cold stripped stream to a prefractionator prior to passing to the product fractionation column; an embodiment of the invention is one, any or all of prior embodiments in this paragraph up through the first embodiment in this paragraph further comprising passing the hot stripped stream to a product fractionation column while passing through the prefractionator. Embodiments of the invention are one, any or all of prior embodiments in this paragraph up through the first embodiment in this paragraph further comprising passing the hot stripped stream to a prefractionator prior to passing to the product fractionation column; embodiments of the invention are one, any or all of prior embodiments in this paragraph up through the first embodiment in this paragraph further comprising fractionating the three products in a product fractionation column: a light naphtha stream taken from the top of the product fractionation column; a heavy naphtha stream taken from a side outlet of a product fractionation column and an unconverted oil stream taken from a bottom of the product fractionation column. Embodiments of the invention are one, any or all of prior embodiments in this paragraph up through the first embodiment in this paragraph further comprising at least one of the following: sensing at least one parameter of the method and generating a signal or data from the sensing; and generating and transmitting signals or data.

A second embodiment of the invention is an apparatus for recovering hydrocracked products comprising a hydrocracking reactor; a separator in communication with the hydrocracking reactor; a thermal stripper in communication with a bottom line extending from the bottom of the separator; a cold stripper in communication with an overhead line extending from the overhead of the separator; a prefractionator in communication with a hot column bottoms line extending from the bottom of the hot stripper column and a cold column bottoms line extending from the bottom of the cold stripper column; a product fractionation column in communication with the top outlet of the prefractionator and the bottom outlet of the prefractionator; and a heavy fractionation column in communication with a bottoms line from the product fractionation column. Embodiments of the invention are one, any or all of prior embodiments in this paragraph up through the second embodiment in this paragraph further comprising a vacuum pump or ejector in communication with the heavy overhead line of the heavy fractionation column. An embodiment of the invention is one, any or all of prior embodiments in this paragraph up through the second embodiment in this paragraph further comprising a reboiler in communication with a product bottom line from the product fractionation column, and the heavy fractionation column is in communication with a stripping line.

A third embodiment of the invention is a process for recovering a hydrocracked product comprising hydrocracking a feed stream with a hydrogen stream over a hydrocracking catalyst in a hydrocracking reactor to provide a hydrocracked stream; separating the hydrocracked stream into a hot liquid hydrocracked stream and a cold liquid hydrocracked stream; stripping the hot liquid hydrocracked stream in a hot stripper column to provide a hot stripped stream; stripping the cold liquid hydrocracked stream in a cold stripper column to provide a cold stripped stream; feeding the cold stripped stream to a product fractionation column; reboiling a product reboiling stream from the bottom of the product fractionation column; returning the product reboil stream to the bottom of the product fractionation column; passing the product bottoms stream to a heavy fractionation column; and feeding the gaseous stripping stream to the bottom of the heavy fractionation column. An embodiment of the invention is one, any or all of prior embodiments in this paragraph up through the third embodiment in this paragraph further comprising feeding the entire cold stripped stream and the entire hot stripped stream to the product fractionation column. Embodiments of the invention are one, any or all of prior embodiments in this paragraph up through the third embodiment in this paragraph further comprising discharging a majority of the diesel in the hydrocracked stream in the heavy distillate stream.

Although not described in further detail, it is believed that one skilled in the art, using the preceding description, can utilize the invention to its fullest extent and can readily determine the essential features of the invention without departing from the spirit and scope of the invention to make various changes and modifications of the invention and adapt it to various uses and conditions. Accordingly, the foregoing preferred specific embodiments are to be construed as merely illustrative, and not limitative of the remainder of the disclosure in any way whatsoever, and are intended to cover various modifications and equivalent arrangements included within the scope of the appended claims.

In the foregoing, all temperatures are shown in degrees celsius and all parts and percentages are by weight unless otherwise indicated.

Claims

1. A process for recovering a hydrocracked product comprising:

hydrocracking the feed stream with a hydrogen stream in a hydrocracking reactor over a hydrocracking catalyst to provide a hydrocracked stream;

separating the hydrocracked stream into a hot liquid hydrocracked stream and a cold liquid hydrocracked stream;

stripping the hot liquid hydrocracked stream in a hot stripper column to provide a hot stripped stream;

Stripping the cold liquid hydrocracked stream in a cold stripper column to provide a cold stripped stream;

feeding the cold stripped stream and the hot stripped stream to a product fractionation column;

passing the product fractionation column bottoms stream to a heavy fractionation column; and

the cold stripped stream is passed to a prefractionator prior to being passed to a product fractionation column.

2. The method of claim 1, further comprising operating the heavy fractionation column under vacuum.

3. The process of claim 1, further comprising withdrawing a heavy distillate stream comprising diesel from the heavy fractionation column.

4. The process of claim 1, further comprising withdrawing a majority of the diesel in the product fractionation column bottoms stream that is fed to the product fractionation column.

5. The method of claim 3, further comprising withdrawing a majority of the diesel fuel from the heavy distillate stream.

6. The method of claim 1, further comprising reboiling a product reboiling stream from a bottom of the product fractionation column, returning the product reboiling stream to the bottom of the product fractionation column.

7. The process of claim 5, further comprising feeding a gaseous stripping stream to the bottom of the heavy fractionation column.

8. The process of claim 1, further comprising splitting the cold stripped stream into an aliquot portion comprising a fractionated feed cold stripped stream and an absorption stream, and feeding the entire fractionated feed cold stripped stream to the product fractionation column.

9. The method of claim 1, further comprising feeding an aliquot of the cold stripped stream to the product fractionation column.

10. The method of claim 1, further comprising at least one of:

sensing at least one parameter of the method and generating a signal or data from the sensing; and generating and transmitting signals or data.

11. An apparatus for recovering hydrocracked products, comprising:

a hydrocracking reactor;

a separator in communication with the hydrocracking reactor;

a thermal stripper in communication with a bottom line extending from the bottom of the separator;

a cold stripper in communication with an overhead line extending from the overhead of the separator;

a prefractionator in communication with a hot column bottoms line extending from the bottom of the hot stripper column and a cold column bottoms line extending from the bottom of the cold stripper column;

A product fractionation column in communication with the top outlet of the prefractionator and the bottom outlet of the prefractionator; and

a heavy fractionation column in communication with a bottoms line from the product fractionation column.